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Executive Summary

India is tipped to be a rapidly growing economy heading towards occupying 3rdplace in the world. However, it needs to be remembered that the growth ofeconomy is dependent upon a crucial assumption that requisite amount ofenergy will be

available at a price that does not adversely 'affect thecompetitiveness of the nation's industry and service sector.

The oil prices have hovered around $50/barrel for long enough to dispel anyoptimism about the oil prices coming down to lower levels inforeseeable future.The import bill for crude oil has jumped to almost double of what it was a yearago. Some analysts predict that oil peak is nearby and oil prices could toucheven $100/barrel mark. Even if one were not to be carried away by this doom'sday predictions, we need to face the facts of life with open eyes and guide thecountry's energy policy to ensure that the happenings in the world oil marketdoes not succeed in derailing the juggernaut of Indian economy.

Geopolitical maneuvers to tie up higher quantities of oil and gas, acquisition of oiland gas equity abroad and intensive exploration of oil and gas at home areindeed welcome steps but not sufficient to ensure energy security and economicrobustness for India. A premium needs to be attached to indigenous resourceexploitation of energy sources-

not just oil and gas.

India's energy use is mostly based on fossil fuels. Although the country hassignificant coal and hydro resource potential, it is relatively poor in oil and gasresources. Asa result it has to depend on imports to meet its energy supplies.

Coal is the major fossil fuel in India and continues to play a pivotal role in theenergy sector. Present use of coal is inefficient and polluting. Hence there isneed for technologies for utilisation of coal efficiently and cleanly, substitution oflesser reserves of oil and gas with abundantly available coal and prolonging thereserves of all the fossil fuels for use of future generations. These requirementscan be met through application of coal gasification technology and following theprinciple of sustainable development.

While thinking about the energy strategy of India, the role of coal cannot bewished away however inconvenient it may be in terms of utilisation efficiency andenvironment. We have to devise technological solutions to make the most out ofthe indigenous resource. Here we shall talk about technologies that can not onlyaugment indigenous energy resources, but also extract energy from coal in formsthat can replace the imported oil and gas products. This would call for a majorchange in the mind set of energy managers so that Companies previously seenas coal producers are now seen as energy producers.

The prime technologies for achieving the objectives of replacement of liquid fuelsand substitution of natural gas would be:

Reducing greenhouse gas emissions as the carbon dioxide produced bycombustion is more than 20 times less harmful to the atmosphere thanmethane



Displacing coal use in environmentally sensitive areas

UCG has the potential to virtuallyeliminate methane emissions to theatmosphere from coal seams whilst allowing the energy stored in the coal to berecovered. UCG will help unearthing the unreachable indigenous resource andsubstitute LNG import.

IGCC will provide a clean coal technology for power generation.

CTL will provide a way of substituting liquid fuels which are imported either inform of crude or the products themselves. Especially, if UCG and GTL arecombined, it can provide energy security to India on a sustained basis bysatisfying the largest user of energy-

the transport sector. This along withbiodiesel has the potential of lending total energy independence to India.

Natural gas is being used for power generation in the country and it is rightly sofor accelerated growth of power sector. There are plans for import of liquefiednatural gas (LNG) and naphtha etc. for power sector mostly by independentpower producers. This could be allowed as a short term measure as dictated bythe market forces. But as a medium to long term measure the natural gas andliquid fuels need to be replaced by coal gas.

The medium to long term targets can be: i) Replacing the natural gas with coalgas in the existing combined cycle power plants ii) Establishment of advanced

The zones which are yet to be opened, plan for full CBM recovery first adthen open zones for mining

4.

UCG production from. "un mineable zones"



New mines yet to be opened

1.

First complete full CBM recovery

2.

Open mines for coal production

3.

UCG production from zones below mining range



Abandoned mines

1. Recover CBM from pillars, compartments by drilling wells

2. If Coal seams are available below "mineable zone", evaluatepossibilities of UCG.



Coal seam below" mineable zone"

1.

CBM recovery

2.

UCG project

It can thus be seen that coal in solid form can continue to support powergeneration and other applications, CBM cansupplement Natural Gasrequirements and through UCG route, syngas so generated can be used eitherfor power generation (IGCC) or for chemicals or liquid petroleum fuel fortransportation network.

As integrated development as proposed would make it imperative thatexploration or oil and gas and exploitation of coal resources be carried in unison.For example, in Cambay basis in Gujarat more than 4000 well have been drilledfor oil exploration / production. Many of these exploratory and development wellswere

dry and abandoned where coal seams were encountered. If petroleum /coal activities were to be performed under "single" licence, UCG operation couldhave started much sooner. As can be seen, exploration / exploitation of oil / gasand coal are both technologically and geologically linked.

Policy initiatives for proposed development of coal fuels



Unified license for Coal, CBM and UCG production along with CO2sequestration.



Unified license for Petroleum, CBM and UCG in those basins wherehydrocarbon (crude oil or natural gas) occurs in coal beds.



Incentives for CBM and UCG production as non-conventional energysource and for emission reduction. Policy options to promote CBM andUCG practiced by U.K., Australia and U.S. include market basedincentives, tax

breaks, feed-in tariffs, direct grants/ supports.



Optimization of energy mix apportioning full role for coal-fuels.



National awareness and the focus commensurate with importance of theenergy security need to be created.



Expediting the process of granting licenses for remaining blocks forexploration of CBM and UCG.

It is very aptly propounded that: "Sustainable development aims to promoteeconomic growth, efficient use of natural resources and their secured long termsupply and protection of environment to ensure survival of the futuregenerations."

India is tipped to be a rapidly growing economy heading towards occupying 3rdplace in the world. However, it needs to be remembered that the growth ofeconomy is dependent upon a crucial assumption that requisite amount ofenergy will be available at a price that does not adversely affect thecompetitiveness of the nation's industry and service sector.

Proper attention needs to be paid to the fragility of this crucial assumption in viewof the current events and what is expected in the future. The oil prices havehovered around $50/barrel for long enough to dispel any optimism about the oilprices coming down to lower levels in foreseeable future. The import bill for crudeoil has jumped to almost double of what it was a year ago. Some analysts predictthat oil peak is nearby and oil prices could touch even $100/barrel mark. Even ifone were not to be carried away by this doom's day predictions, we need to facethe facts of life with open eyes and guide the country's energy policy to ensurethat the happenings in the world oil market does not succeed in derailing thejuggernaut of Indian economy. Geopolitical maneuvers to tie up higher quantitiesof oil and gas, acquisition of oil and gas equity abroad and intensive explorationof oil and gas at home are indeed welcome steps but not sufficient to ensureenergy security and economic robustness for India. A premium needs to beattached to indigenous resource exploitation of energy sources-

not just oil andgas.

With a gross domestic product (GDP) growth of 8 per cent set for the Tenth FiveYear Plan (2002-07), the energy demand is expected to grow at 5.2 per cent.India's incremental energy demand for the next decade is projected to be amongthe highest in the world, spurred by sustained economic growth, rise in incomelevels and increased availability of goods and services.

The projected requirement of commercial energy is estimated at about 412MTOE and 554 MTOE respectively in 2007 and 2012; the commercial energydemand is estimated to grow at an average rate of 6.6 per cent and 6.1 per centrespectively during the period 2002-07 and 2007-12. However, the demand maybe less by 5 per cent and 10 per cent during 2006-07 and 2011-12 respectivelydue to increasing use of information technology (IT) and prevalence of e-Commerce, which will mainly affect the demand of energy in transport sector.

Estimated Energy Demand in India based on extrapolation of "Business asUsual" scenario as reported by Asean India Business Portal website report is:

Primary

Unit

Demand in (Original Units)

Demand (MTOE)

2006-07

2011-12

2006-07

2011-12

Coal

Mt

460.50

620.00

190.00

254.93

Lignite

Mt

57.79

81.54

15.51

22.05

Oil

Mt

134.50

172.47

144.58

185.40

Natural Gas

BCM

47.45

64.00

42.70

57.60

Hydro Power

BKwh

148.08

215.66

12.73

18.54

Nuclear Power

BKwh

23.15

54.74

6.04

14.16

Wind

BKwh

4.00

11.62

0.35

1.00

Power

Total Commercial Energy

411.91

553.68

Non-Commercial Energy

151.30

170.25

Total Energy Demand

563.21

723.93

India's energy use is mostly based on fossil fuels. Although the country hassignificant coal and hydro resource potential, it isrelatively poor in oil and gasresources. As a result it has to depend on imports to meet its energy supplies.The geographical distribution of available primary commercial energy sources inthe country is quite skewed, with 77 per cent of the hydro potential located in thenorthern and north-eastern region of the country. Similarly, about 70 per cent ofthe total coal reserves are located in the eastern region while most of thehydrocarbon reserves lie in the west.

As per current projections, India's dependence on oil imports is expected toincrease. The demand of natural gas also outpaces supply and efforts are beingmade to import natural gas in the form of liquefied natural gas (LNG) and pipedgas. If the present trend continues, India's oil import dependency is likely to growbeyond the current level of 70 per cent.

The success of liberalization policy and economic reforms introduced in thecountry is largely dependent on adequate availability of energy resources ataffordable prices and oil has a significant place in it. Therefore any disruptions inoil supplies would hamper progress of the country. Thus from consideration ofnational self reliance, security and assured energy supply, production of oil inIndia from alternate source i.e. coal is justified.

Coal is the major fossil fuel in India and continues to playa pivotal role in theenergy sector. Oil and natural gas are very limited hence India is a net importerof hydrocarbons. India is heavily dependent on oil imports and the trend is likelyto remain same. Economic growth of the country is tied up with regular supply ofoil and any disruptions could drastically arrest the growth. Oil imports are a drainon foreign exchange reserves since they constitute about 26% of import bill.More and more of natural gas is being used for power generation leaving lesserallocations for fertilisers and chemicals etc where it is essential and convenient.Indian coals in general are of inferior quality.

Present use of coal is inefficient and polluting. Hence there is need fortechnologies for utilisation of coals efficiently and cleanly, substitution of lesserreserves of oil and gas with abundantly available coals and prolonging thereserves of all the fossil fuels for use of future generations. These requirementscan be met through application of coal gasification technology and following theprinciple of sustainable development.

While thinking about the energy strategy of India, the role of coal cannot hewished away however inconvenient it may be in terms of utilisation efficiency andenvironment. We have to devise technological solutions to make the most out ofthe indigenous resource. Here we shall talk about technologies that can not onlyaugment indigenous energy resources, but also extract energy from coal informsthat can replace the imported oil and gas products. This would call for a majorchange in the mind set of energy managers so that Companies previously-seenas coal producers are now seen as energy producers.

The prime technologies for achieving theobjectives of replacement of liquid fuelsand substitution of natural gas would be:

Reducing greenhouse gas emissions as the carbon dioxide produced bycombustion is more than 20 times less harmful to the atmosphere thanmethane



Displacing coal use in environmentally sensitive areas

UCG has the potential to virtually eliminate methane emissions to theatmosphere from coal seams whilst allowing the energy stored in the coal to berecovered. UCG will help unearthing the unreachable indigenous resource andsubstitute LNG import.

IGCC will provide a clean coal technology for power generation.

CTL will provide a way of substituting liquid fuels which are imported either inform of crude or the products themselves. Especially, if UCG and GTL arecombined, it can provide energy security to India on a sustained basis by

satisfying the largest user of energy-

the transport sector. This along withbiodiesel has the potential of lending total energy independence to India.

India's Energy Puzzle

As per the available estimates, India's 2020 consumption of energy is expectedco be somewhere approximately 800 Mtre. To

realise the target, each segmentof the value chain needs two and half times growth between now and 2020 thuscalling for massive investments in infrastructure creation on grand scale throughefforts from public, private sector and joint partnerships. The

All energy sources need to be explored and exploited to the hilt while determiningoptimum fuel mix with options of coal, oil, gas, hydel, renewables and nuclear.

It is essential to understand internalization of environment cost imposed bydifferent forms of energy and what this means for energy choices to be madekeeping the long-term perspective in mind.

For India to join theleague of developed nations, we must ensure that the poweris produced at affordable rates and competition is introduced in the sector toenhance efficiency, consumer responsiveness and reduced prices.

Keeping electricity prices affordable and competitiveinternationally, will dependon the price of fuel viz. coal, oil product or gas as fuel constitutes 60% of the costof gas.

India has relatively large reserves of coal (250 billion tonnes) compared to crudeoil (728 million tonnes) and natural gas (686 billion cubic meters). Coal meetsabout 60% of the commercial energy needs and about 70% of the electricityproduced in India comes from coal.

Advanced technologies when applied to Indian coal resources, can improve theefficiency and minimize environmental impacts of coal utilisation. A balance isnecessary between short term imperatives and long term possibilities to enablesustainable development. To pursue such a strategy technologies are availableand are also under development.

Since reserves of oil andnatural gas are meager, they need to be substitutedwith coal to the extent feasible. At the same time all the three fuels, especiallycoal needs to be conserved for the future generations. The energy sectorrequires

efficient, clean and dependable energy

supplies. Hence coal has to beutilized with multi pronged strategy i.e. higher efficiency, environmentalacceptance, prolonging its availability and as replacement for oil etc. which ispossible only through sustainable development by use of modern technologies.

If the gaseous form of fuels could be obtained on a large scale from mineableand unmineable coal resources the versatility of coal as a fuel resource could begreatly enhanced. The major advantage of gasification is that coal is convertedinto agaseous fuel which is easy to handle and is a clean form of energy. In thegaseous form it enables substitution of petroleum products and natural gas. Thesynthesis gas has wide range of applications. It can be used in a combined cyclesystem for efficient

and clean generation of electric power. It is suitable for themanufacturing of hydrogen and chemicals such as ammonia, methanol, aceticacid; as substitute natural gas, and as a reducing gas for metallurgical purposesetc. It can be used in multipurposeplants for the simultaneous production ofelectric power, chemicals/ fertilisers and fuels which also improve the economicsof coal gasification.

India's Coal Resources

India is endowed with rich deposits of coal and lignite in different sedimentarybasins of varying dimensions. The bulk of the coal resource of 235 billion tonnesis contained in older basins like the Gondwana basin. Large lignite deposits of100 billion tonnes occur in younger basins of Gujarat, Rajasthan and Tamil Nadu.A characteristic feature of these basins is the development of very thick coal andlignite seams (20-80m) over a large stretch of the coal/lignite fields. In fact, oneof the thickest seams (138m) of the world is in Indian coal fields.

The present updated total coal resources of the country as per the latest nationalinventory as on 1.1.2004 is 2,45,692.42 million tonne for coal seams of 0.9m andabove in thickness and upto 1200m depth from surface. The inventory is basedon sub-surface data accrued from regional (includingpromotional) and detaileddrilling carried out by GSI, CMPDI, SCCL and MECL. Out of the total resources,Gondwana coalfields contribute 2, 44,785.47 million tonne while the Tertiarycoalfields account 906.95 million tonne.

The depth-wise breakup of the total resource reveals that about 65.6% of coalresource are confined within 0-300m depth level in which maximum share comesfrom Orissa (43.9 bt), followed by Jharkhand (36.1 bt) excluding Jharia coalfield,

Underground production of coal peaked in the late seventies and has fallenslowly since then. Surfacemining, on the other hand, has soared from16 to 160million tonnes per annum. Of the 588 mines in India, 355 are under-ground, butopencast accounts for 75 percent of production and employs only 16 percent ofthe total mining work force. Productivity is higher in the opencast sector.

Almost 80% of today's coal comes from surface strip mines (opencast mines),which is much safer.

The above estimates do not show large reserves of deep seated coal in Gujarat.

The CBM resources as per Directorate General of Hydrocarbons (DGH), Ministryof Petroleum & Natural Gas (MoP&NG) is tabulated here under:

Table Prognosticated Resource of CBM

S.No.

State

Coalfield/Block

Area ofdelineatedblock (Sq.KM)

PrognosticatedCBM Resourceas per DGH

Remarks

1

WestBengal

In trillioncubicfeet

Inbillioncubicmeter

Marginalresource maybe inJharkhand

NorthRaniganj

232

1.030

29.17

EasternRaniganj

500

1.850

52.38

Birbhum

250

1.000

28.32

Sub Total

982

3.88

109.87

2

Jharkhand

Jharia

69.20

East &WestBokaro

93.37

Northaranpura

340.54

Sub Total

503.11

6.178

174.93

3

MadhyaPradesh

Sohagpur

495

3.030

85.79

Sohagpur

500

Satpura

500

1.000

28.32

4

Gujarat

CambayBasin

2400-3218*

11* to19.4

311*-549.39

May not beimmediatelyavailabl3ebecauseONGC hasactiveconventionalOil& Gasoperations.

*As perAdvancedResourcesInc.

GrandTotal

2980.11-

3798.11

25.088-

33.488

710.39

948.73

In India, the Reliance Gas has carried out comprehensive geologic assessmentof coal/lignite basins based on which about 20,000 km2of area has beenidentified as prospective for CBM with estimated in place resource of about20,000 billion cubic metres. The recoverable reserve of about 800 billion cubicmetres and gas production potential of about 105 million metre cum per day overa period of 20 years has been estimated. CBM potential is thus about 1.5 timesthe present natural gas production in India, which is capable of generating about19000 MW of electricity. The potential of gas production in India is given in Tablebelow:

Essar has already drilled three wells to a depth of 1450 metres and is producingthe gas experimentally.

Neyveli Lignite Corporation (NLC) proposes to taken up a Underground CoalGasification (UCG) project in a suitable lignite block in Rajasthan under Ministryof Coal's S&Tprogramme and Department of Science & Technology funding at atotal cost of Rs.1,125 lakhs part of a joint venture project with Coal India Limited(CIL). Great Eastern Energy Corporation Limited (GEECL) and Essar are alsoinvolved in initial field studiesin Raniganj South and Gujarat respectively.

The coal occurs in the Lower Gondwana (Permian) coal-bearing Karharbari/Barakar and Raniganj formations where there can be in excess of 100m of totalcoal thickness. The Barakar formation contains some 50 coal seams that aregreater than l.5m thick whilst the Raniganj formation includes 10 seams rangingfrom 1m to 11m thick. The Damodar Valley basin is the most heavily mined areain India containing high rank, gassy coal. It is suggested that based on thesecharacteristics Jharia, Bokaro, North Karanpura, and the Raniganj coalfieldsshould be the primary targets for CBM development.

Test results for the Barakar coals in the Jharia coalfield report the majority of gascontents to be between 7 and 17m3/t (dry ash free). The results indicate the gascontent increases uniformly with the depth of coal.

A number of encouraging factors are reported:



Average cumulative coal thickness (surface to 1200m) in the order of 90m

Results from test wells show gas flows of 1000-2000 m3/ d from a singleseam at depth



average gas production from a single test well (5 coal seams farce) of6500m3/ d over a 1.5

year period (production testing continuing) with aninitial maximum gas flow of 23,000m3/ d, and cumulative gas flow of 7million m3



Water production of about 6m3/ d, which has been shown to be of a goodquality suitable for agricultural use and also recycling for field operations



local market for CBM for power generation with a larger market identifiedwithin 30km.

The main Gondwana coal basins are rifted intra-cratonic grabens having thicksequence of coal seams, and hold considerable prospects for coal bed methane.The major part of Indian Gondwana coals (mostly up to 300 m depth) is of lowrank, far below the threshold value of thermogenic methane generation.However, high rank coals, amenable for generation of coal bed methane, mostlyoccur in untapped deeper parts of basins covered by younger sediments.

Tertiary coals in petroliferous basins of Cambay, Upper Assam and Assam-Arakan may be prospective due to reported higher gas content, which is probablystored in the coal after generation from deeper-lying hydrocarbon source beds ormay be of biogenic origin.

Government of India has awarded 16 CBM blocks for exploration and productionof Coal Bed Methane in different coal fields of India. The commercial productionof CBM from few of these awarded blocks may start by 2006-07. These blocksmay yield a peak production of about 23 MMSCMD of CBM in the country.

CMM/AMM/VAM

An initial review of historic mining practices in India and discussions with CIL andothers would indicate few opportunities exist for AMM development. This is dueto the relatively shallow depth of mining, low gas contents and use of noncavingmethods of underground coal mining (board and pillar). However, if longwallmining expands, the potential application of AMM could increase in the

mediumto long term.

Methane emission studies from working mines of India reported most of thedegree three gassy mines (10 cubic m/ton), are confined in the four DamodarValley coal fields, viz. Raniganj, Jharia, Bokaro and North Karanpura in Bihar andWest Bengal. In these areas, the thickest bituminous coals are extensivelydeveloped in the Barakar measurers and in Raniganj measures of Lower andUpper Permian age, respectively. The Barakar coal seams are superior toRaniganj coal seams as coal bed methane targets. Based on thickness andburial depth, rank and quality of coal has the greatest coalbed methane potentialin India.

In India, underground coal production currently comprises approximately 25percent of total production, and annual tonnage of underground coal producedthere has remained essentially steady over the past two decades (World Coal,1999). Singh (2001a) observes India's trend toward

a decrease in the share ofunderground coal production. That trend, however, appears to derive primarilyfrom a dramatic increase in surface production in recent years rather than from adrop in absolute production from underground mines (World Coal, 1999). Thecoal seams currently being exploited are not particularly gassy, and methaneconcentrations in ventilation airflows even at the gassiest mines are low, typicallybelow 0.3 percent.

power generation capacity in the country (as on 31 March 2002,) about 59,386MW is coal based and 2,745 MW is lignite based, totaling to 62,131 MW or 59per cent.

Indigenous coal is likely to remain the most stable and least cost option for thebulk of India's energy needs in the foreseeable future. This is so because coalbased thermal power generation capacity has a shorter gestation period andlower specific investment costs when compared to other locally availablecommercial energy resources like nuclear or hydropower. Thus, there is need forconcerted efforts for the overall developments of the sector in future Plans.Energy security concerns underscore the need to further develop indigenous coalproduction in the foreseeable future.

When technologies like CBM, CMM, AMM, VAM and UCG are employed inconjunction with CTL technology the reach of coal based fuels will be widened tocover even transport fuels and substitution of natural gas which are bothimported and weigh heavily on the trade balance for the country. Apart from thisthese technologies will harness those fuel resources which are hithertoconsidered unreachable/ unusable.

Methane is a natural product arising out of the decay of organic matter and ascoal deposits were formed with increasing depths of burial and risingtemperatures and pressures over geological time, a proportion of the methaneproduced was adsorbed by the coal. Whereas in a natural gas reservoir such assandstone the gas is held in the void spaces within the rock, methane in coal isretained on the surface of the coal within the micropore structure. Suchadsorption is maintained by the lithostatic and hydrostatic pressures. The releaseof these pressures allow methane to escape from the coal. The presence ofsignificant amounts of methane in coal is familiar to coal miners as the gas isreleased due to the relaxation of pressure and fracturing of the strata duringmining activity, and can give rise to serious safety concerns if not managedproperly. Many explosions have occurred over the years leading to tiledevelopment of "methane drainage" where the gas is drained from the strata bypumping from boreholes drilled above the working face. This practise oftenyielded significant quantities of methane, which was on occasion used to fire thecolliery boilers.

Methane. build-up in coal mines has caused many mine explosions, killingthousands of miners worldwide. In gassy mining conditions, creating a safe workenvironment requires that coal mining companies develop practices that allowthem to assess the amount of gas that will be liberated during the miningprocess, and determine the best way to remove the gas from the mine. No matterwhether the gas is drained from the seam or adjoining strata in advance ofmining or from the gob, the purpose is the same: remove enough gas from themine so that the ventilation system can dilute the remaining gas that

will beemitted into the mine to acceptable levels. Gas drainage systems are often notdesigned with the goal of optimizing gas recovery because of budget constraintsand the overriding concerns of safety. Furthermore, for the same reasons, dataavailable

to the investigator for assessing the potential of developing acommercial coal mine methane resource estimate may be limited.

Successful development of a coalmine methane project requires a thoroughunderstanding of the size and production potential ofthe gas resource. The coalmine methane resource comprises the volume of gas distributed throughout thecoal and surrounding strata, often referred to as gas-in place.

100% recovery of the gas-in-place is virtually impossible. Tec1znicallyrecoverable coal

mine methane resources is the quantity of gas that isrecoverable by utilizing proven modes of extraction while employing existingtechnology. The commercially extractable portion of the technically recoverableresources is the resen1es. A developer's estimate of reserves will varydepending on assumptions regarding the technology used for recovery andchanges that may take place in future economic conditions.

The methane continues to emit from the mine after closure, and recently theconcept of collecting the gas from abandoned mines to provide an energy sourcewhich would otherwise be waste has been developed. The concept is generallyreferred to as Coal Mine Methane (CMM)

The amount of methane in a coal bed depends on the quality and depth of thecoal deposit. In general, the higher the energy value of the coal and the deeperthe coal bed beneath the surface-

resulting in more pressure from overlying rockformations-

the more methane the deposit holds. Coal stores six to seven timesmore gas than the equivalent rock volume of a conventional gas reservoir.

Many mining companies will pre-drill to allow some of this gas to escape, but asthe mining operation grows, new long walls are constructed. When coal isextracted and the wall moved, gas escapes fromthe now-collapsing roof. Gaspockets could also be disrupted above and below the coal seam, something thatmust be monitored and measured.

These systems can exhaust significantamounts of methane to the atmosphere in low concentrations.

There are three things to consider in this process:



They want to drain the coalmine methane for mine safety and efficiency;



They want to sell the gas as fuel and feedstock;



And, they want to certify that it qualifies for greenhouse gas emissionsreductions.



Methane from coal beds can be recovered from coal seams by:



Draining gas from working coal mines



Extracting gas from abandoned coal mines



Producing

gas from unmined (virgin) coal using surface boreholes

Mine gas utilisation schemes are encouraged by governments and internationalagencies that recognise the energy benefits of a waste material and the netreductions in greenhouse gas emissions achievable. Virgin CBM productionschemes, which are independent of mining, contribute indirectly to a reduction ingreenhouse emissions by replacing coal burning.

CBM

Coalbed methane is located wherever coal is found.

Only a small percentage of these resourcescan be recovered with currenttechnology, and a still smaller percentage can be recovered profitably.

Gas can be produced from coals of nearly every rank; however, some of the lessattractive coals (e.g., lignite) may require substantial thicknesses of coal todevelop adequate reserves.

A typical one-foot thickness of coal six hundred feet deep is capable ofcontaining as much gas as a typical sandstone reservoir five thousand feet deep.Another unique characteristic of coalbed production is its producing behavior. Inmost cases, initial production of gas is quite low while water production may behigh. As the water is withdrawn, and the bottom-hole pressure decreases in thereservoir near the well bore, gas production gradually increases. During the firstfew producing months the water-producing rate will continue to decreaseaccompanied by an increase in the gas-producing rate, until a pseudo-steadystate occurs for both phases.

Water pressure holds methane in the coal bed. To release the gas, its partialpressure must be reduced by removing water from the coal beds. Once thepressure is lowered, the gas and water move through the coal bed and up thewells.

At first, coalbed methane wells produce mostly water, but over time, the amountof water declines andgas production rises as the bed is dewatered. Waterremoval may continue for several years. The water is usually discharged on thesurface or injected into aquifers.

Whether a coalbed will produce commercial quantities of methane gas dependson the coal quality, its content of natural gas per ton of coal, the thickness of thecoal bed (s), the reservoir pressure and the natural fractures and permeability ofthe coal. CBM is generally more pure right out of the ground when compared withconventional naturalgas reservoirs.

CBM is recovered from virgin coal (for this reason it is sometimes referred to asVCBM) by releasing the gas located both within the coal and adsorbed onto thesurface of the coal. Coal seams are injected with a high pressure water, foamand sand mix. The high pressure fractures the coal for some distance around theborehole. The sand holds the fractures open, enabling the water and gas to flowto the well bore and hence to the surface.

CBM offers a method of extracting methane from unworked

coal withoutdetrimentally affecting the physical properties of the coal. This provides manybenefits:



When carried out on its own it facilitates exploitation of the coal resourcein areas where the coal would be unlikely to be worked by traditionalmining methods.

Methane quality is such that it has the potential to be fed directly into thegas distribution network. This is one distinct difference with CMM whichhas higher carbon dioxide content and so is not suitable for directintroduction.

Coal bed

methane development is accompanied by a number of environmentalproblems and human health hazards.

1. Disposal of water removed from coal bed methane wells

CBM produced water may have high concentrations of dissolved salts and othersolids. Water discharges may flood the property of landowners, causing erosionand damaging soils and plants. Coalbed methane water in Montana, USA has anaverage sodium adsorption ratio of 47, over 30 times the level that can damagesoils, causing crop yields to decline.

2. Drinking water levels drop in surrounding areas. The level of some drinkingwater wells near coalbed methane development has dropped as water has beenremoved from coal beds.

In the San Juan Basin, USA methane gas is seeping up in fields, forests andrivers. Methane seeps. often have companion "dead zones"' where methane-saturated soils have starved the roots of vegetation, killing some trees nearly 100years old. High levels of methane asphyxiate

rodents in burrows near seeps.While such seeps are not new, they appear to be more frequent and severesince the advent of coalbed methane, development. Some scientists andresidents believe that coalbed methane development is aggravating the problem.

Methane seeping into drinking water wells and under people's homes has causeda health hazard. On the Pine River near Bayfield, Colorado, Amoco bought outand relocated several families because of high levels of methane present in theirbasements and drinking water. Other chemicals may vent following coalbedmethane development, including carbon dioxide and hydrogen sulfide.

5. Underground fires

Underground fires plague coal-rich areas. They often strike where extensivemining has occurred, because shafts and

tunnels help circulate the oxygenneeded for coal to burn below the earth's surface. Coalbed methanedevelopment can exacerbate this problem when water is removed to release thegas and oxygen gets in. Two underground coal fires are burning on the SouthernUte Reservation in southwest Colorado in an area where coalbed methane hasbeen extracted. In June 2002, an underground coal fire in Glenwood Springs,Colorado sparked a month-long wildfire in the area that destroyed people'shomes and property.

6. Destruction of land and harm to wildlife

The wells are then connected with pipelines, compressor stations and roads,leaving scars on the land that will last for decades. Wildlife habitat is fragmented,and migration corridors are disrupted. High road densities

and the constantvehicular traffic needed to monitor and maintain wells and pipelines areespecially disruptive to wildlife.

CBM Produced Water

Coalbed methane produced water often has high sodium adsorption ratio (SAR)values-the ratio of sodium, calcium and magnesium concentrations-

highconcentrations of metals-

iron, manganese and barium-

and variable saltcontent. These minerals may affect soil permeability or be toxic to certain plantspecies. Ideal conditions for CBM produced water for irrigation are areas withcoarse-textured soil and salt-tolerant crops.

Native high salt tolerant grasses and forbs can be planted around impoundmentsand discharge sites to maximize the use of CBM produced water and reduceerosion, as well as being used in bioremediation of brine contaminated soils.

Economics of CBM production depend on reducing the cost of handling producedwater. Beneficial uses for produced water offer the best alternative to high-costre-injection procedures.

Various treatment or pretreatment applications may be necessary beforeproduced water can be funneled for alternative uses.

Alternatives to re-injection of CBM produced water fall in five main categories:water impoundments for stock and wildlife, irrigation, surface discharge, andrecreational and industrial uses.

Water management options for CBM produced water include use in theoperational activities of industries in the producing region. Common industrialuses include coal mines, animal feedlots, cooling towers, car washes, enhancedoilrecovery and fire protection.

CMM/AMM

Coal mining releases the gases naturally occurring in coal seams. The methaneflow from the mine workings depends on the gas content of the coal seams,thickness and distance of adjacent coal seams from the worked seams and themethod and rate of mining. Atmospheric emissions can be reduced by capturinga proportion of the gas before it enters mine airways, piping it to the surface andusing it as fuel gas or as a chemical feedstock.

CMM drainage technologies only capture a proportion of the gas released intomine workings. Captures achieved in individual mining panels can typically rangefrom 30% to 80% depending on the drainage technology used, the geology andthe mining conditions.

Coal mine methane is produced as a result of the fracturing of coal and coalmeasures strata as part of historical and current mining operations releasing themethane which had been adsorbed within it.

However, the commercial exploitation of methane has the potential, now wellproven, of harnessing the gas safely and beneficially to generate electricity andcan provide considerable benefits:



An uncontrolled danger and potential surface hazard to individuals andproperty is harnessed and greatly reduced if not removed.



Harmful ventilation tothe atmosphere is reduced with a significantreduction of greenhouse gas emissions.



Electricity available to local users, especially in cases where formercolliery sites are developed for industry and commerce.

The coal mining industry has made good progress in delivering high-grade CMMto natural gas markets. Using gob gas has proven more challenging, althoughpioneers in the coal, gas, and power industries also have identified severalpotentially beneficial gob gas uses, as listed below.



Fuel for coal dryers and-other gas-fueled mine equipment.



Fuel for electricity production.



Feedstock for gas enrichment systems that upgrade the gas to pipelinequality.



Supplemental fuel for industrial and utility boilers (delivered in dedicatedpipelines).

Since gob gas (as well as any medium-

to high-quality methane) may be cofiredwith the primary fuel in a variety of existing combustion units including boilers,furnaces, and kilns, it can partially replace common fuels (e.g. coal, oil, andnatural gas). The fuelthat cofired gob gas replaces is referred to herein as"avoided" fuel. Cofiring gob gas, as explained in the next section, can providegreater value to the buyer than that of the avoided (replaced) primary fuel. Thisreport refers to an "enhanced" gob gas

value which is the sum of the avoidedfuel plus associated environmental and operational benefits.

Environmental Benefits

The most important and valuable environmental benefits can be achieved bycofiring gob gas in quantities that are small as compared with total boiler heat(Glickert 1997). The benefits include reductions in NOx, SOx, and particulates(opacity):

NOx Reduction. When properly configured and optimized, gob gas cofiring maybe able to reduce NOx emissions from the entire boiler.

SOx Reduction. Cofiring methane reduces SOx emissions.

Reduced Opacity. Utilities may be able to use gas to reduce stack opacity andthereby avoid plant derating.

Operational Benefits

Improved Ash Quality. If a utility intends to sell its ash to the concrete industry

toavoid high disposal costs, gob gas cofiring may enhance this possibility byreducing carbon levels in the ash to saleable limits.

Utilities sometimes experience sparking problems in their electrostaticprecipitators. Studies show that gas cofiring maymitigate the condition.

Derate Mitigation. H coal processing equipment inadequacies limit a boiler (eitherduring pulverizer or feeder outages or because the plant has been forced to uselow sulfur coal that contains less heat per pound), gob gas use may mitigate thederating condition by allowing more fuel to enter the boiler.

Rating Increase. In some cases, a boiler's operating limit may be driven by itsforced draft fan rating, even though it may not have reached its total heat releasecapacity. In thisevent, the operator may be able to cofire small increments of gobgas without backing off the coal feed-

thus ending up with an increased plantrating.

Lower Turndown. If a boiler can rely primarily on gas during periods of lowdemand, the minimum operating load can be reduced by almost half of its coal-fired minimum (e.g. from 45 to 25 percent of

full load). Having lower turndownswill result in fewer shutdowns and reduced boiler start-up costs. Not only doesgas retain its flame stability at low loads,its heat rate is much better than coal inthis range. To gain this benefit, however, the boiler operator must have access tolarger gas flows than are typically available from a gob gas project.

Reduction of Slag Buildup. Some utilities have fired gas in coal boilers for shortperiods or continuously to remove harmful slag deposits. This removal strategy ismuch less expensive than shutting the boiler down and mechanically removingthe deposits. As with the improved turndown ratio described above, however,anoperator must have access to an adequate gas supply.

The following two benefits are intangible and probably minor:

Increased Efficiency (Lower Heat Rate). Methane often burns in large coalboilers with somewhat better combustion characteristics than the coal itself. Thisresults in a small efficiency gain that is partially offset by the need to evaporatethe water formed during methane combustion and the fact that the boilers werebuilt to maximize radiant heat transfer from coal and not gas.

Reduced O&M Costs. There are many ancillary systems operating in a coalfiredboiler that process, handle, and transport coal, as well as remove coal ash.

Theoretically, these systems will cost less to operate and maintain when gas isfired as a partial substitute for coal because they are handling less coal.

CO2 Sequesterisation and CMM production

CO2 is preferentially adsorbed on coal, relative to methane and nitrogen.Therefore, if CO2 is injected into an abandoned coal mine, the CO2 will displaceadsorbed methane. Injection and subsequent adsorption of CO2 onto the carboncontained in the coal remaining within and peripheral to an abandoned coal minewill trap the CO2, effectively sequestering it from the atmosphere and therebyreduce the amount of this greenhouse

gas (GHG) in the atmosphere.

Physical determinants for the effectiveness of this process are the adsorptivecapacity of the coal for the gases, the permeability of the coal, the amount of coalexposed to the CO2, and the pressure at which the mine can hold the gas. Theeconomic feasibility of the envisioned project is determined by the unit cost of theC02 sequestered versus the value of the greenhouse gas (GHG) reductioncredits that could be generated.

Abandoned coal mines could also be used as a carbonsink because CO2 hasan affinity for adsorbing to coal, that is greater than methane, and will effectivelydisplace the methane molecules from the adsorption sites within the micro porestructure of the coal. The advantages of injection into an abandoned coal mineversus an unmined coal bed are identified below:

The large exposed surface area in the mine workings will facilitate the adsorptionof the CO2;

The mining process enhances fracturing of the coal and therefore thepermeability to the flow of gas into the unmined perimeter as well as into the coalremaining as pillars;

The water saturation of the coal near the mine workings will be low because themining activity. has lowered the pressure and drained the water, facilitatingmovement of gas into the coal; and

The injection pressure will be low, so the cost of compression will be low.

The following parameters are significant in determining the C02 storage capacityof a mine:

The size of the mine workings;

The thickness of the coal;

The permeability of the coal;

The pressure at which the mine can be operated as a storage vessel;

The pressure at which methane is contained in the coal;

The adsorption isotherm of the coal for C02, methane, and nitrogen, and; and

The distance to which the C02 will penetratebeyond the outer walls of the mine.

COAL MINE VENTILATION AIR METHANE (VAM)

Ventilation air methane (VAM), that is, methane in the exhaust air fromunderground coal mines, is the largest source of coal mine methane, accountingfor about 60% of the methaneemitted from coal mines Unfortunately, because ofthe low concentration of methane (0.3-1.5%) in ventilation air, it is difficult to usethe methane beneficially. However, oxidizing methane to CO2 and water reducesits global warming potential by 87%. A potential way to oxidize the methane is byuse of a thermal flow reversal reactor (TFRR). Different technologies for gainfullyutilizing VAM are described below which are at different stages of development.

Thermal Flow-Reversal Reactor

Figure below shows aschematic of the Thermal Flow-Reversal Reactor (TFRR).The equipment consists of a bed of silica gravel or ceramic heat-exchangemedium with a set of electric heating elements in the center. The TFRR processemploys the principle of regenerative heat exchange between a gas and a solidbed of heat exchange medium. To start the operation, electric heating elementspreheat the middle of the bed to the temperature required to initiate methaneoxidation (above l,000oC

[l,832°F]) or hotter. Ventilation

air at ambienttemperature enters and flows through the reactor in one direction and itstemperature increases until oxidation of the methane takes place near the centerof the bed.

The hot products of oxidation continue through the bed, losing heat to the far sideof the bed in the process. When the far side of the bed is sufficiently hot, thereactor automatically reverses the direction of ventilation airflow. The ventilationair now enters the far (hot) side of the bed, where it encounters auto-oxidationtemperatures near the center of the bed and then" oxidizes. The hot gases againtransfer heat to the near (cold) side of the bed and exit the reactor., Then, theprocess again reverses.

As USEPA (2000) points out, TFRR units are effectively employed worldwide tooxidize industrial VOC streams. Furthermore, the ability of MEGTEC'sVOCSIDIZER to oxidize VAM has been demonstrated in the field.

Catalytic Flow-Reversal Reactor

Catalytic flow-reversal reactors adapt the thermal flow-reversal technologydescribed above by including a catalyst to reduce the auto-oxidation temperatureof methane by several hundred degrees Celsius (to as low as 350°C [662°F).CANMET has demonstrated this system in pilot plants and is now in the processof licensing Neill and Gunter (Nova Scotia) Ltd. of Dartmouth, Nova Scotia, tocommercialize the design (under the name VAMOX). CANMET is also studyingenergy recovery options for profitable turbine electricity generation. Injecting asmall amount of methane (gob gas or other source) increasesthe methaneconcentration in ventilation air to make the turbine function efficiently. Waste heatfrom the oxidizer is also used to pre-heat the compressed air before it enters theexpansion side of the gas turbine.

Energy Conversion from a Flow-Reversal Reactor

There are several methods of converting the heat of oxidation from a flow

reversal reactor to electric power, which is the most marketable form of energy inmost locations. The two methods being studied by MEGTEC and CANMET are:

Use water as a working fluid. Pressurize the water and force it through an air to

water heat exchanger in a section of the reactor that will provide a nondestructivetemperature environment (below 8000C [1472oF]). Flash the hot pressurizedwater to steam and use the steamto drive a steam turbine generator.

If a market for steam or hot water is available, send exhausted steam to thatmarket. If none is available, condense the steam and return the water to thepump to repeat the process.

Use air as a working fluid. Pressurize ventilation air or ambient air and send itthrough an air-to-air heat exchanger that is embedded in a section of the reactorthat stays below 8000C (1472oF). Direct the compressed hot air through a gasturbine-generator. If gob gas is available, use itto raise the temperature of theworking fluid to more nearly match the design temperature of the turbine inlet.Use the turbine exhaust for cogeneration, if thermal markets are available.

Since affordable heat exchanger temperature limits are below those used inmodern prime movers, efficiencies for both of the energy conversion strategieslisted above will be fairly modest. The use of a gas turbine, the second methodlisted, is the energy conversion technology assumed for the cost estimates in thisreport.

At a VAM concentration of 0.5 percent one vendor expects an overallplant efficiency in the neighborhood of 17 percent after accounting for powerallocated to drive the fans that force ventilation air through the reactor.

Other Technologies

Other technologies that may prove to be able to playa role in and enhanceopportunities for VAM oxidation projects are briefly described below.

Concentrators

Volatile organic compound (VOC) concentrators are one possibly economicaloption that is under evaluation by USEPA for its application to VAM.

Ventilation air typically contains about 0.5 percent methane concentration byvolume, or 500 ppm. Conceivably, a concentrator might be capable of increasingthe methane concentration in ventilation air flows to about 20 percent. This highlyreduced gas volume with a higher concentration of methane might servebeneficially as a fuel in a gas turbine, reciprocating engine, etc.

The fluid bed concentrator consists of a series of perforated plates or trayssupporting the adsorbent

medium (activated carbon beads). The processexhaust stream enters from the bottom, passing upward through the adsorptiontrays, fluidizing the adsorbent medium to enhance capture of organiccompounds. The adsorbent medium, which is now heavier because of

theadsorbed organic material, falls to the bottom of the adsorber section and is fedto the desorbcr. The desorber increases the temperature of the medium, causingit to release the concentrated organic material into a low volume, inert gasstream.

Lean-Fuel Gas Turbines

A number of engineering teams are striving to modify selected gas turbinemodels to operate directly on VAM or on VAM that has been enhanced with moreconcentrated fuels, including concentrated VAM (see "Concentrator" sectionabove) or gob gas. These efforts include:

Carbureted gas turbine.

A carbureted gas turbine (CGT) is a gas turbine inwhich the fuel enters as a homogeneous mixture via the air inlet to an aspiratedturbine. It requires a fuel/air mixture of 1.6 percent by volume, so most VAMsources would require enrichment. Combustion takes place in an externalcombustor where the reaction is at a lower temperature (1200°C [2192°F]) thanfor a normal turbine thus eliminating any NOx emissions.

Lean-fueled turbine with catalytic combustor. The CCGT technology beingdeveloped oxidizes VAM in conjunction with a catalyst. The turbine compressesa very lean fuel/air mixture and combusts it in a catalytic combustor. The catalystallows the methane to ignite at a lower, more easily achieved temperature.

Lean-fuel micro turbine. Ingersol-Rand Energy Systems, is developing amicrotubine that is planned to operate on a methane-

in-air mixture of less than 1percent. The microturbine is rated at 70 kW and consists of a generator, gasifierturbine,

combustor, recuperator, power turbine, and generator. The system isenclosed in a sound-attenuating enclosure and can be located indoors oroutdoors. Ingersol-Rand recently introduced a 250 kW microturbine to the powerindustry. Additional R&D effort is required to complete the system design on the70 kW unit and to adapt the 250 kW unit to run in a lean-fuel mode. IngersolRandis seeking funding to further pursue this market.

Lean-fueled catalytic microturbine. Two US companies, FlexEnergy andCapstone Turbine Corporation, are jointly developing a line of microturbines,starting at 30 kW, that will operate on a methane-in-air mixture of 1.3 percent.Each unit's components fit inside a compact container that requires no fieldassembly. The single moving part, rotating on an air bearing, is a shaft on which

is mounted the compressor and the turbine expander. Other components include:a recuperator that preheats the VAM mixture, a catalytic combustion chamberwith low-temperature ignition, a generator, and a

Hybrid coal and YAM-fueled gas turbine. CSIRO is also developing aninnovative system to oxidize and generate electricity with VAM in combinationwith waste coal. CSIRO is constructing a 1.2-MW pilot plant that cofires wastecoal and VAM in a rotary kiln, captures the heat in a high-temperature air-to-airexchanger, and uses the clean, hot air to power a gas turbine. Depending on siteneeds and economic conditions, VAM can provide from about 15 to over 80percent (assuming a VAM mixture of 1.0 percent) of the system's fuel needs,while waste coal provides the remainder.

VAM Used as an Ancillary Fuel

While the primary focus of this assessment is on strategies that oxidize majorfractions of global VAM emissions, a brief mention of technologies that use VAMonly as an ancillary or supplemental fuel is in order. Such technologies rely on aprimary fuel other than VAM and are able to accept VAM as all or part of theircombustion air to replace a small fraction of the primary fuel. The largestexample of ancillary VAM use occurred at the Appin Colliery in Australia, where54 one-MW Caterpillar engines used mine ventilation air containing VAM ascombustion air Similarly, the Australian utility, Powercoal, is installing a system touse VAM as combustion air for a large coal-fired steam power plant. A workingexample of this application is shown below:

Supplemental Fuel Example: Appin Colliery, Australia



Installed in 1995



54 xl MW IC Engines Produce Power from Gob Gas



VAM Used as Feed Air, Supplies 7% of Energy

Underground Coal Gasification

In comparison with conventional coal mining and modern steam power plant,UCG with combined cycle power generation offers the overall environmentaladvantages of:



Lower particulate emissions, noise and visual impact on the surface



Less water used (this is important in many of the mining areas in China)



Lower risk of surface water pollution



Reduced methane emissions from coal mining



No dirt handling and disposal at mine sites



No coal washing and fines disposal at mine sites



No ash handling and disposal at power station sites



Less

SO2 and NOx



Lower energy consumption as less materials and product transport



Less heavy surface transport



Smaller land area occupied



Fewer liabilities after mine abandonment.

Additional benefits of the UCG power generation approach are:



Lower occupational health and safety risks (fewer miners underground)



Lower capital and operating costs compared with conventional systems



Flexibility of access to mineral



Larger coal resource exploitable.

There are coal reserves deep underground in the State of Gujarat. The 'in-situ'north Gujarat reserves which are estimated at 63 billion tonnes occur at a depthof 800 to 1700 metres which is beyond the limits of conventional methods ofmining in India. If this resource is exploited on a large scale by using the latesttechnologies of UCG, it could generate gas equivalent to 200,000 BCM.

Coal gasification is the process of converting coal to a gaseous fuel throughpartial oxidation. The coal is fed into a high-

temperature pressurized containeralong with steam and a limited amount of oxygen to produce a gas. The gas isknown as synthesis gas or syngas and mainly consists of carbon monoxide andhydrogen. The gas is cooled and undesirable components, such as carbondioxide and sulphur are removed. The gas can be used as a fuel or furtherprocessed and concentrated into a chemical or liquid fuel.

Integrated gasification combined-cycle (IGCC) systems combine a coalgasification unit with a gas fired combined cycle power generation unit. The firststage is the coal gasification process as mentioned above. The second stagetakes the cleaned gas and burns it in a conventional gas turbine to produceelectrical energy,and the hot exhaust gas is recovered and used to boil water,creating steam for a steam turbine which also produces electrical energy. Intypical planes, about 65% of the electrical energy is produced by the gas turbineand 35% by the steam turbine.

In general the advantages of IGCC are:



It can achieve up to 50% thermal efficiency. This is a higher efficiencycompared to conventional coal power plants meaning there is less coalconsumed to produce the same amount of energy, resulting in lower ratesof carbon dioxide (CO2) emissions



It produces about half the volume of solid wastes as a conventional coalpower plant.



It uses 20-50% less water compared to a conventional coal power station.



It can utilise a variety of fuels, like heavy oils, petroleum cokes,

and coals.



Up to 100% of the carbon dioxide can be captured from IGCC, making thetechnology suitable for carbon dioxide storage.



Carbon capture is easier and costs less than capture from a pulverisedcoal plant



A minimum of 95% of the sulphur is removed and this exceeds theperformance of most advanced coal-fired generating units currentlyinstalled.



Nitrogen oxides (NOx) emissions are below 50ppm. This is lower thanmany of today a (TMs most advanced coal-fired generating units.



The syngas produce from a gasifier unit can be burned in a gas turbine forelectricity generation, or used as a fuel in other applications, such ashydrogen-powered fuel cell vehicles

Coal to Liquid Technology

Once Coal is gasified and converted to a mixture of CO + H2, through FischerTropsch reaction, the synthesis gas can be converted to liquids. This aspect hasbeen fully covered in our article of August 2005-

GTL taking on to markets.Executive Summary of the same is reproduced below:

GTL taking on to markets. Executive

Summary

Ever increasing consumption of fossil fuel and petroleum products has been amatter of concern for the country for huge out-go of foreign exchange on the onehand and increasing emission causing environmental hazards on the other. Thecurrent annual import bill of crude oil in terms of foreign exchange is around Rs.60, 400 crores. Diesel is mainly consumed for transport; road transport eats upalmost 75% while the Railways account for the rest.

Oil provides energy for 95% of transportation and the

demand of transport fuelcontinues to rise. The requirement of Motor Spirit is expected to grow from littleover 7 MMT in 2001-02 to over 10 MMT in 2006-07 and 12.848 MMT in 2011-12and that of diesel (HSD) from 39.815 MMT in 2001-02 to 52.324 MMT in 2006-07and just over 66 MMT in 2011-12.

The capitalization and infrastructure associated with diesel amounts to hundredof billions of dollars, and it is safe to say that diesel will remain the fuel of choicefor some time to come. However, biodiesel1s contribution could be substantialand well timed in providing an option which will help meet the environmental andstrategic concerns of the country, while allowing the financial realities ofinfrastructural investments in diesel technology to be compensated.

The same logic holds good for GTL-Diesel, which can not only provide a sourceof environmentally compliant fuel but also help avoid capital expenditure onsetting up additional refining capacity and product upgradation schemes. To addto it, if GTL is produced by use of indigenous resources like CTL and BTL, itwould do the yeoman service of giving the Indian energy basket a semblance ofEnergy Independence.

ONE OF THE HOTTEST TRENDS in the global petroleum industry in 1997involved a technology that is three fourths of a century old.

Economic conversion of natural gas to synthetic fuels, one of the "Holy Grails" ofthe energy industry for decades, took startling steps in 1997.

For the first time since the discovery of the Fischer-Tropsch synthesis process in

1923, gas-to-liquids conversion processes may be competitive with conventionalpetroleum products on the world market. And the technology doesn't require anoil price of $30-40/bbl, as was the case with the failed synthetic fuels projects ofthe late 1970s and early 1980s. The oil price at present is close to touching$70/bbl and is not likely to return to previous lows for the foreseeable future.

The GTL industry is poised for a major expansion based in Qatar, but also inNigeria and Australia. The expansion is being funded by the major oil companies,in some cases in tandem with synthetic fuel companies and national oilcompanies. The projected expansion of the industry is based on favourablemarket conditions in addition to advances in technology. High oil and natural gasprices, declining capital investment costs, and improvements in technology thatallow large scale production facilities are important factors in the industry'sexpansion.

India is slated to be a fast growth economy with predictions thatby 2050 it will bethe third largest economy in the world. However the achievement of theenvisioned growth is subject to a number of enabling factors being in the rightplace. Energy is certainly one of the most important prime movers of theeconomy. Anydisturbance in availability of energy in terms of either reliability oreconomics can jam the wheels of the juggernaut of the economy.

India will have to look at alternative energy with a greater urgency andGTL/CTL/BTL certainly merits being one of them.

Small Sized GTL Plants

Most world-class GTL technology is in large plants associated with gas fields of5-500 Trillion cubic feet (Tcf). However it is essential to find a cost effectivesolution for smaller GTL plants to monetise flared gas, associated gas, Coalbased or biomass based production. M/s Syntroleum, Rentech and SynfuelsInternational are working in this direction and are willing to license thetechnology.

F-T conversion of coal (CTL)

The main difference between processes for producing F-T liquids from coalcompared to production from natural gas is in the syngas production step. Thereforming step is replaced by a pressurized oxygen-blown gasifier when usingcoal.

F-T conversion of biomass (BTL)

According to Choren it takes 5 tons of biomass toproduce 1 ton of sundiesel and1 hectare generates 4 tons of sundiesel. A plant producing 13,000 tons per yearwould need the biomass of 50,000 ha. In recent years the German set-aside areaamounted to roughly 1 million ha. This could generate 4 million tons of sundiesel,which is about 13 percent of .current diesel use in Germany.

Relevance of GTL to India

Despite two encouraging discoveries of natural gas in India and import of LNGfrom two terminals on the West Coast, India will remain a supply driven market.The available gas would better be transmitted and distributed by pipelines anduse for energy efficient applications in power generation, industry, commercialestablishments, residential sector and transport sector. For Gas to Liquids (GTL)India will. have to look outside India for gas resources. May be the gas equityabroad could provide a suitable opportunity. Special political efforts could pay offwell if the landlocked countries like Kazakhstan, Turkmenistan and Russia weretargeted for bookinggas resources.

However Coal to Liquids (CTL) and Biosyngas to Liquids (BTL) are thepossibilities where India can use its own resources. While talking about CTL,

India has possibility of exploiting a large resource via Underground coalgasification (UCG),

which is given up as unreachable. There are coal reservesdeep underground in the State of Gujarat. The 'in-situ' north Gujarat reserveswhich are estimated at 63 billion tonnes occur at a depth of 800 to 1700 metreswhich is beyond the limits of conventional methods of mining in India. If thisresource is exploited on a large scale by using the latest technologies of UCG itcould generate gas equivalent to 200,000 BCM. UCG has a special attribute thatit helps enhance the quantity of indigenous fossil fuels that were hithertoconsidered virtually non-existent-unexploitable. The technology of UCG is provenelsewhere to some extent but, the use of the latest and the most cost

effectivetechnology available today (CRIP) needs to be imported and tried out right away(zero date starts with the commencement of first trial) so that at least inforeseeable future we will be able to increase the indigenous content in theenergy basket of India. .

UCG has a virtue that it will cut down the Syngas Production (Costing 50% ofGTL Project) from the GTL project. With the price of unmineable coal taken aszero, UCG could provide an economic option for Syngas.

CBM is another source of gas which may not be large enough in size to afford itstransmission and distribution. Here the small sized GTL technology being offeredby a number of companies may be of good use.

To top it all BTL would be from renewable resources and hence would never getexhausted. India has a large base of agriculture and forests where thistechnology (BTL) being used in Germany could provide a significant degree ofEnergy Independence as envisioned by the President of India.

Syngas, or synthesis gas, produced from fossil fuels or biomass, is shaping up tobecome a crucial intermediate in emerging energyand fuel solutions. Syngascan be combined with emerging downstream technologies for gas-to-liquids(GTL) processes, methanol-to-olefins (MTO) conversion, coal-to-liquids (CTL)conversion and fuel cells. It also is used as a feedstock for high-value, chemicalprocesses such as ammonia, hydrogen and methanol.



We need to procure several very large so-called stranded gas fields,immense fields of natural gas that have been discovered but are too farfrom developed gas markets to have any value (the landlockedcountrieslike Kazakhstan, Turkmenistan and Russia were targeted for booking gasresources). Indian government would have to forge agreements with a fewfriendly nations to purchase rights to produce this gas and convert it toliquid fuels on location.



We

need to commence UCG trials without any further loss of time andimport the best possible technology-to ensure commercial success oflarge scale UCG projects which can then feed the GTL projects to producediesel which is the most dominant fuel in India's energy basket.



We may collaborate with countries like Germany and immediately importthe BTL technology and set up a number of plants based on biomasswaste which presently posses a disposal problem.



Obviously, the economics of GTL/CTL/BTL would improve over a period oftime. (May not be much of a problem at current price of crude oil.)Requisite policy support may be given for the growth of this industry whichalone can give India the energy independence that it badly needs.

Conclusions

India is highly dependent on imported oil with. a heavy drain on foreign exchangeearnings. This trend is not likely to change very much in foreseeable future.Finding of any large reserves of oil in the country is not in sight. Oil can besubstituted with coal, but for

certain applications it has to be converted into liquidform. Several experts have already recommended the coal gasification route forliquefaction of Indian coals. Considering several aspects, the option of coal to oilseems to be an unavoidable strategy

for India.

Natural gas is being used for power generation in the country and it is rightly sofor accelerated growth of power sector. There are plans for import of liquefiednatural gas (LNG) and naphtha etc. for power sector mostly by independentpower producers. This could be allowed as a short term measure as dictated bythe market forces. But as a medium to long term measure the natural gas andliquid fuels need to be replaced by coal gas.

The medium to long term targets can be: i) Replacing the natural gas with coalgas in the existing combined cycle power plants ii) Establishment of advancedpower generation technologies based on coal gas i.e., fuel cell. iii) Commercialplants for coal to oil and coal refinery. iv) Sell reliance and security in energysector v) Substitution of exhaustible with renewable energy sources.

The present use of coal mostly through direct combustion is inefficient with highlevels of pollution. The efficiency cannot be improved much due to technologicallimitations and it is

very expensive to control the pollution. India is looking foralternate technologies, more efficient, environmentally benign and economicallyattractive. Coal gasification fits into these requirements. IGCC technology is thebest alternate option for power generation in India.

The setting up of coal to oil conversion plants should not be evaluated purelyfrom commercial angle, but security, sell reliance and conserving oil should meritserious consideration. Coal to oil technology can be considered on thesamefooting as atomic energy which had paid dividends by bringing the country to sellreliant status.

A concept of coal refinery is mooted now and may be put in practice as a longterm strategy to substitute the imported oil.

To progress on the technology front, for next 20-30 years our country should takepro-active leads on technologies like-

Methane capture and its utilization from coal mines is not being undertaken inIndia due to:

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Lack of latest technology

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Lack of expertise and experience

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Pervasive perception that commercial viability of exploitation andutilization of Methane is doubtful.

Opportunities exist for the development of a range of clean coal energies from in-situ coal seams focused on CBM and UCG. The development and exploitation ofthese fuels is likely to provide environmental, safety and financial benefits.Technology is being developed for using low methane concentrations in mineventilation air but it is unlikely to be commercially viable without support fromgovernment. VAM utilisation might also divert effort from improving gas

captureand utilisation at working coal mines, which could have safety implications.

Evaluation of coal properties, construction of adsorption isotherm, and study ofgeological setting of coal basins should be an integral part of initial researchefforts.

It is desirable to work out the techno-economic viability of a project afterR&D efforts are completed and before exploration and exploitation are taken up.

The potential production rate of a virgin CBM reservoir can be under-estimated, ifcare is not taken to protect seam permeability from damage during drilling andtesting. 'Clean drilling' techniques, as practiced by leading operators in the UK,should therefore be introduced to ensure that CBM prospects are correctlycharacterized and optimum CBM production rates are attained.

UCG

The technology is highly relevant and very promising to India. Two sites in Indiaone in Rajasthan and another in Bengal-Bihar initially appear to be suitable forapplication of underground coal gasification. Many more areas could beamenable.

There are coal reserves deep underground in the State of Gujarat. The 'in-situ'north Gujarat reserves which are estimated at 63 billion tonnes occur at a depthof 800 to 1700 metres which is beyond the limits of conventional methods ofmining in India. If this resource is exploited on a large scale by using the latesttechnologies of UCG, it could generate gas equivalent to 200,000 BCM.

UCG provides a radical approach to mine mouth power generation that enablesthe energy in coal to be released without the need to extract, process, transportand combust it. UCG virtually eliminates greenhouse gas emissions associatedwith coal extraction. Hitherto, the potential net greenhouse gas emissionmitigation benefits of UCG power generation compared with conventional coalextraction and coal-fired power plant has received little attention.

It can thus be seen that coal in solid form can continue to support powergeneration and other applications, CBM can supplement Natural Gasrequirements and through UCG route, syngas so generated can be used eitherfor power generation (IGCC)' or for chemicals or liquid petroleum fuel fortransportation network.

As integrated development as proposed would make it imperative thatexploration or oil and gas and exploitation of coal resources be carried in unison.For example, in Cambay basis in Gujarat more than 4000 well have been drilledfor oil exploration / production. Many of these exploratory and development wellswere dry and abandoned where coal seams were encountered. If petroleum /coal activities were to be performed under "single" licence, UCG operation couldhave started much sooner. As can be seen, exploration / exploitation of oil / gasand coal are both technologically and geologically linked.

Policy initiatives for proposed development of coal fuels

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Unified license for Coal, CBM and UCG production along with CO2sequestration.

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Unified license for Petroleum, CBM and UCG in those basins wherehydrocarbon (crude oil or natural gas) occurs in coal beds.